As is well known in the hydrocarbon industry, many wells require “stimulation” in order to promote the recovery of hydrocarbons from the production zone of the well.
One of these stimulation techniques is known as “fracturing” in which a fracturing fluid composition is pumped under high pressure into the well together with a proppant such that new fractures are created and passageways within the production zone are held open with the proppant. Upon relaxation of pressure, the combination of the new fractures and proppant having been forced into those fractures increases the ability of hydrocarbons to flow to the wellbore from the production zone.
There are a significant number of fracturing techniques and fluid/proppant compositions that promote the formation of fractures in the production zone and the delivery of proppants within those fractures. The most commonly employed methodologies seek to create and utilize fracturing fluid compositions having a high viscosity that can support proppant materials so that the proppant materials can be effectively carried within the fracturing fluid. In other words, a viscous fluid will support a proppant within the fluid in order that the proppant can be carried a greater distance within the fracture or in some circumstances carried at all. In addition, fracturing fluids are commonly designed such that upon relaxation of viscosity (or other techniques) and over time (typically 90 minutes or so), the fluid viscosity drops and the proppant is “dropped” in the formation, and the supporting fluid flows back to the wellbore. The proppant, when positioned in the fracture seeks to improve the permeability of the production zone in order that hydrocarbons will more readily flow to the well. An effective fracturing operation can increase the flow rate of hydrocarbons to the well by at least one order of magnitude by reducing well to formation communication impairment. Many wells won't produce long term in an economic manner without being stimulated by methods such as fracturing.
Fracturing fluid compositions are generally characterized by the primary constituents within the composition. The most commonly used fracturing fluids are water-based or hydrocarbon-based fluids, defined on the basis of either water or a hydrocarbon being the primary constituent of the specific composition. Each fracturing fluid composition is generally chosen on the basis of the subterranean formation characteristics and the economics of conducting a fracturing operation at a particular well or group of wells.
In the case of hydrocarbon-based fluids, in order to increase the viscosity of liquid hydrocarbon, various “viscosifying” additives may be added to the hydrocarbon-based fluid at the surface such that the viscosity of the hydrocarbon-based fluid is substantially increased thereby enabling it to support proppant. As is known, these hydrocarbon-based fluids may include other additives such as breakers and/or other additives to impart various properties to the fluid as known to those skilled in the art. The most commonly used viscosifying additives are phosphate esters and metal complexors that are used to create fluids having moderate to high viscosities.
During a fracturing operation, the fracturing composition (without any proppant) is initially pumped into the well at a sufficiently high pressure and flow rate to fracture the formation. After fracturing has been initiated, proppant is added to the fracturing fluid, and the combined fracturing fluid and proppant is forced into the fractures in the production zone. When pressure is released and over time (typically 90 minutes), the viscosity of the fracturing fluid drops so that the proppant separates or drops out of the fracturing fluid within the formation and the “de-viscosified” fracturing fluid flows back to the well where it is removed up the well back to the wellhead at surface.
Problems in this type of fracturing are the volumes and cost of liquid hydrocarbon required and the attendant issues relating to the disposal of the liquid hydrocarbon that has been pumped downhole and ultimately recovered from the well. As a result, in some cases the industry has moved away from pure hydrocarbon-based fracturing fluids in favor of those technologies that utilize a high proportion of gas (usually nitrogen) as the fracturing fluid, or cheaper fluids such as aqueous fluids.
The use of a high proportion of gas has several advantages including minimizing formation damage, reducing fluid supply costs as well as a reduction in the fluid disposal costs of fluid that is recovered from the well. For example, whereas liquid hydrocarbon may reduce the ability of a production zone to flow by adherence to pore throats in the matrix rock of the formation and/or by hydrostatically holding back the formation with a column of flow back fluid in the well, high gas compositions will often minimize such damage and/or effects and will otherwise migrate from the formation more readily. In addition, gas injected and thus recovered from a well can simply be released to the atmosphere thereby obviating the need for decontamination and disposal of a substantial volume of non-gaseous materials recovered from the well.
With high ratio gas fracturing compositions, the characteristics of the compositions can be similarly controlled or affected by the use of additives. Generally, gas fracturing compositions can be characterized as a pure gas fracturing composition (typically a fluid comprising around 100% CO2 or nitrogen) or energized and foamed fluids (typically a fracturing composition comprising less than about 75% nitrogen by volume when dealing with hydrocarbon based fluids).
A pure 100% gas fracturing composition will have minimal viscosity and instead will rely on high turbulence to transport proppant as it is pumped into the production zone. Unfortunately, while such techniques are effective in limited batch operations, the need for expensive, highly specialized, pressurized pumping, mixing and containment equipment substantially increases the cost of an effective fracturing operation. For example, a fracturing operation that can only utilize a batch process is generally limited in size to the volumetric capacity of a single pumping and containment unit. As it is economically impractical to employ multiple units at a single fracturing operation, the result is that very high volume gas fracturing operations can only be effectively employed in relatively limited circumstances. For example, a pure gas fracturing operation would typically be limited to pumping 300-32,000 kg of sand (proppant) into a well and may also be limited to the type of proppant that can be used in some circumstances.
The use of non-energized, energized and foamed fluids as fracturing fluids are generally not limited to batch operations as fluid mixing and pumping equipment for such fluids is generally not at the same scale in terms of the complexity/cost of equipment that is required for pure gas operations. In other words, the mixing and pumping equipment for a non-energized/energized/foamed fluid fracturing operation is substantially less expensive and importantly, can produce effectively large and continuous volumes of fracturing fluid mixed with most types of available proppant. That is, while a 100% gas fracturing operation may be able to deliver up to 32,000 kg of proppant to a formation, a non-energized/energized/foamed fluid fracturing operation may be able to deliver in excess of 10 times that amount.
The characteristics of energized and foamed fluids are briefly outlined below as known to those skilled in the art.
An energized fluid will generally have less than about 53% (volume % at down hole pressure and temperature) gas together with a liquid phase typically either water or hydrocarbon based. An energized fluid is further characterized by a continuous fluid phase with gas bubbles that are not concentrated enough to interact with each other to increase viscosity. For example, the overall viscosity of an energized fluid comprised of a fluid phase and nitrogen gas may be in the range of 200 cP which is a “mid-point” between the viscosity of a typical hydrocarbon-based phase (300 cP) and a nitrogen gas phase (0.01 cP). As is known, and in the context of this description, viscosity values measured in centipoise (cP) are dependent on shear rate and temperature. In this specification, all viscosity values are referenced to a shear rate of 170 sec−1 and 293 K.
Foams will generally have greater than about 53 vol % gas but less than about an upper limit of 75 vol % gas with the remainder being a gelled liquid hydrocarbon phase. Stable hydrocarbon foams generally have an upper limit that is lower than that of water foams, which for water is about 85 vol %. Foams are characterized as having a continuous fluid film between adjacent gas bubbles where the gas bubbles are concentrated enough to interact with each other to increase viscosity. Foams require the addition of foaming agents that promote stability of the gas bubbles. For example, the viscosity of a hydrocarbon foam will typically be in the range of 200-1000 cP which may be 2 to 10 times greater than the viscosity of the hydrocarbon liquid phase (20-800 cP) and many times greater than the viscosity of the gas phase (0.01-0.1 cP).
Hydrocarbon based fluids behave differently than water based fluids in terms of the solubility preferences between nitrogen and carbon dioxide, the two most commonly used fracturing gases as well as other factors as discussed below. Water based fluids have similar solubility properties with either gas under a large range of pressures and temperatures, wherein nearly all the added gas forms a second and distinct gas phase when creating a foam or emulsion. In comparison, hydrocarbon based fluids have a tendency to combine with carbon dioxide to form a single miscible phase under some temperatures and pressures whereas nitrogen has a very small solubility in hydrocarbon fluids. As such, carbon dioxide miscibility with the hydrocarbon based fluid, depending on the pressure and temperature, can range in effect from completely involving all mixed gas to leave a single miscible liquid phase without a gas phase to having nearly a liquid hydrocarbon phase with a gas phase and no miscibility effects.
In addition, when a hydrocarbon based fluid includes chemical additives at sufficient concentrations to cause various effects, and with carbon dioxide forming a single miscible phase with the hydrocarbon, a hydrocarbon/carbon dioxide system may have the effect of diluting the active chemicals and changing the fluid properties.
Further still, the amount of carbon dioxide that will form a single miscible phase with hydrocarbon based fluids is highly variable depending on the pressure, temperature and specific blend of components of the hydrocarbon fluid which may be affected by pressure and temperature in the wells during a fracturing operation.
Furthermore, hydrocarbon based fluids have a greater chemical sensitivity to carbon dioxide gas compared to nitrogen gas. The most commonly used breaker technology for hydrocarbon fluids is a high pH breaker such as magnesium oxide as the active ingredient. Carbon dioxide creates a low pH in trace water which can counteract the high pH breaker to affect the designed fluid chemistry to form viscosity and reduce it again over an intended quantity of time.
There are also differences in safety implications regarding hydrocarbon based fluids and water based fluids. For example, the normal injection methods of water based fracturing fluids into a well and ultimately the production formation will utilize either of or a combination of tubing, casing or coiled tubing. For hydrocarbon based fracturing fluids, these fluids are normally restricted from being injected via coiled tubing due to the safety risk in the event of a coiled tubing leak or burst, and accordingly would normally be restricted to injection via casing, tubing or manifolded casing and tubing. Moreover, the safety risk is intensified when compressed gases are combined with the hydrocarbon based fluid.
Mists
As is known, when the gas concentration is increased above about 75% in a hydrocarbon based fluid or above about 85% for water based fluids, (typically 90-97%), the stability of a typical foam will decrease, such that the foam will “flip” such that the gas phase becomes continuous and the liquid hydrocarbon phase is dispersed with the gas phase as small droplets or in larger slugs. This is commonly referred to as a “mist”. The viscosity of a mist will generally revert to a “mid-point” of viscosity close to that of the gas (i.e. approximately 1-3 orders of magnitude lower than that of a foam) with the result being that the ability to support proppant based on viscosity is substantially reduced.
As a result, fracturing compositions generally avoid the formation of mists and instead favor stabilizing foams and otherwise maximizing viscosities.
A review of the prior art shows that the active promotion and use of a mist as a fracturing composition within hydrocarbon based fracturing fluids has not been considered.
For example, U.S. Pat. No. 7,261,158 discloses a high concentration gas fracturing composition that is a “coarse foam”; U.S. Pat. No. 6,844,297 discloses fracturing compositions including an amphoteric glycinate surfactant that increases viscosity and enables viscosity control of the compositions through pH adjustment; U.S. Pat. No. 6,838,418 discloses fracturing fluid including a polar base, a polyacrylate and an “activator” that ionizes the polyacrylate to a hydroscopic state; U.S. Pat. No. 4,627,495 discloses methods using carbon dioxide and nitrogen to create high gas concentration foams; U.S. Pat. No. 7,306,041 discloses acid fracturing compositions that contain a gas component; US Publication 2007/0204991 describes a method and apparatus for fracturing utilizing a combined liquid propane/nitrogen mixture; US Publication 2006/0065400 describes a method for stimulating a formation using liquefied natural gas; and, US Publication 2007/0023184 describes a well product recovery process using a gas and a proppant.